Production of fluids from oil and gas reservoirs containing high levels of hydrogen sulfide (H2S) requires the separation of the H2S from both the produced oil and the produced natural gas and the safe disposal thereof. There are at least two widely practiced methods of processing natural gas with high H2S. In one known method, the entire H2S-containing natural gas stream (also referred to herein as sour gas) is dehydrated, compressed, and reinjected at high pressure in an underground formation. In another known method, the gas is sweetened in an amine unit using amine scrubbing, followed by dehydration, and optionally, fractionation to extract propane and butane prior to being sold as sales gas (containing mostly methane, and some ethane and nitrogen). The H2S and CO2 removed from gas processing in the amine unit (collectively referred to as acid gas) are sent to a Sulfur Recovery Unit (SRU) where the H2S is converted to elemental sulfur via the well-known Claus reaction.
In U.S. Pat. No. 8,869,890, the concept of bulk removal of H2S in existing gas processing plants with high H2S feeds was introduced. The total H2S entering the plant could be reduced, effectively providing additional processing capacity, and the high-H2S permeate gas could be compressed and re-injected into an underground formation. Produced gas from such high H2S reservoirs is usually water saturated and/or contains a relatively high concentration of water along with the high H2S. Feeds with high H2S and saturated water can degrade the membrane separation performance of some membranes when water condenses on the membranes. Such membranes include membranes made with cellulose acetate and cellulose triacetate polymers. The membranes therefore require water-saturated feeds to be pre-treated to avoid any water condensation. Sour gas dehydration is practiced in known gas processing plants using molecular sieve dehydration to dehydrate the feed gas but current molecular sieve dehydration practice is limited to feeds with concentrations up to 20 to 30 volume % H2S. Some significant challenges are known with the use of molecular sieves for high H2S concentration feeds. For one, as a pre-treatment upstream of a membrane, dehydration of sour feeds with molecular sieve zeolites has shown the potential to form carbonyl sulfide (COS), which can cause operational challenges for acid gas treatment and meeting the total sulfur specification on the product gas and LPG. Zeolites may act as a catalyst to promote the reaction of H2S+CO2→COS+H2O. Secondly, downstream of a membrane, limited operational experience is available for molecular sieve dehydration of sour gas permeate after compression at greater than 30 volume % H2S. This represents a challenge as the permeate stream from the membrane unit can reach concentrations of 50 volume % or more based on the expected acid-gas removal target.
In other parts of a gas processing plant with a high H2S feed, amine units are used to remove acid gases, such as H2S and CO2, from a sour gas stream thus producing an enriched acid gas stream and an enriched hydrocarbon stream. Amine units have at least one amine absorber vessel and at least one regeneration vessel. As a non-limiting example, the acid gas stream may include a small amount of hydrocarbons, typically methane (C1), water vapor, carbon dioxide (CO2), and hydrogen sulfide (H2S). The acid gas stream is then sent to a Claus unit which, is well known to those skilled in the art of treating acid gases that include relatively high concentrations of hydrogen sulfide (H2S). The Claus unit may convert at least a portion of the H2S in the acid gas stream into elemental sulfur, which may be subsequently transported and sold for commercial uses like fertilizer and production of sulfuric acid.
The acid gas stream sent to the Claus unit is high in H2S concentration (e.g., greater than 50 volume %) and at low pressure (1-3 barg). Typically, this acid gas comes from the amine regenerator and is cooled for water dewpointing due to a limit on water vapor in the Claus unit feed. Cooling is provided by air coolers or by using cooling water. In arid regions, availability of cooling water is limited and air cooling is limited by the high ambient temperatures. When adequate cooling to remove water cannot be provided, the flow of gas to the Claus units has to be limited. A reduction in the acid gas processing by the Claus units creates a gas processing bottleneck which in turn limits oil production. This problem is most acute in the summer months, when the amine regenerator overhead cooler cannot cool down the gas and condense water out due to high ambient temperatures. While portable coolers can be employed, they are expensive to operate and increase the risk of H2S exposure each time they are connected and removed from the process lines. Glycol dehydration is not an option as any carryover glycol can thermally shock the Claus catalyst and the low-pressure stream would either have to be compressed or a very large glycol unit would be needed to process the low-pressure gas stream. Aside from being expensive, and being inefficient for low pressure streams, there is little or no experience with molecular sieve dehydration at H2S concentrations above 20-30 volume %, severely limiting their use. Salt driers are also disadvantaged, because of corrosion and disposal of H2S saturated brine considerations.
It would be desirable to have economical and simple ways of overcoming the above described challenges.